Method of fault detection and recovery in a tubing string located in a hydrocarbon well, and apparatus for same

ABSTRACT

A method of fault detection and recovery in a tubing string located in a hydrocarbon well is described, the tubing string having a plurality of valves, each valve having a control unit, each control unit being connected in series to a power-line providing power and communication, each of the control units being independently controllable. The method includes: detecting a short circuit, fault or failure in one of the control units of the tubing string via an output of the power-line; causing individual control units to be selectively isolated from the power-line via a circuit interrupting device; and determining one or more control units associated with the short circuit, fault or failure via the output of the power-line while individual control units are selectively isolated from the power-line. A method of fault protection in a tubing string, and an apparatus and system for the same are also described.

RELATED APPLICATION DATA

The present disclosure claims priority to, and the benefit of,provisional U.S. patent application No. 62/624,082, filed Jan. 30, 2018,the content of which is incorporated herein by reference.

TECHNICAL FIELD

The present disclosure relates to tubing strings located in hydrocarbonwells for oil recovery, and in particular, to a method of faultdetection and recovery in a tubing string located in a hydrocarbon well,a method of fault protection in a tubing string located in a hydrocarbonwell, and an apparatus and system for same.

BACKGROUND

Wellbores used in injection wells receive injection sleeves carryingmechanical, power and data equipment used in oil recovery operations.Wellbores uses in production wells can also receive mechanical, powerand data equipment. The wellbore environment is challenging due toenvironmental conditions, remoteness and access restrictions.Accordingly, various design constraints are involved in the design ofinjection sleeves and supporting control systems, which often varybetween applications due to differences in the formation in which thewellbore is located and production objectives, among other factors.

SUMMARY

The present disclosure relates to a method of fault detection andrecovery in a tubing string located in a hydrocarbon well, a method offault protection in a tubing string located in a hydrocarbon well, andan apparatus and system for same. The teachings of the presentdisclosure can be used to detect faults in downhole telemetry systems,recover from faults in downhole telemetry systems and/or protect againstfaults in downhole telemetry systems, depending on the embodiment. Theteachings of the present disclosure may be applied to a short circuit,fault or failure in a control unit of downhole telemetry systems.

In accordance with one embodiment of the present disclosure, there isprovided a method of fault detection and recovery in a tubing stringlocated in a hydrocarbon well, the tubing string having a plurality ofvalves, each valve having a control unit, each control unit beingconnected in series to a power-line providing power and communication,each of the control units being independently controllable, the methodcomprising: detecting a short circuit, fault or failure in one of thecontrol units of the tubing string via an output of the power-line;causing individual control units to be selectively isolated from thepower-line via a circuit interrupting device; and determining one ormore control units associated with the short circuit, fault or failurevia the output of the power-line while individual control units areselectively isolated from the power-line.

In some examples, the short circuit, fault or failure is detected inresponse to a determination that one or more characteristics of theoutput of the power-line has changed by more than a threshold amount.

In some examples, the one or more characteristics of the output of thepower-line is a current of the power-line.

In some examples, the method is performed by a master controller coupledto the control units.

In some examples, the master controller is located above the hydrocarbonwell.

In some examples, the control units communicate with the mastercontroller via half-duplex communication.

In some examples, the master controller is a programmable logiccontroller.

In some examples, the tubing string is an injection string.

In some examples, the method comprises: after the determining one ormore control units associated with the short circuit, fault or failure,selectively isolated the one or more control units associated with theshort circuit, fault or failure are from the power-line.

In some examples, the method comprises: before detecting the shortcircuit, fault or failure: causing a condition of the valves of thetubing string to be set in accordance with a first valve configuration;and causing an injection fluid to be injected into the tubing string inaccordance with a first valve configuration; after the determining oneor more control units associated with the short circuit, fault orfailure: causing a condition of the valves of the tubing string to beset in accordance with a second valve configuration, wherein the secondvalve configuration excludes as possibilities operating states in whichthe one or more control units associated with the short circuit, faultor failure selectively isolated from the power-line are controlled; andcausing the injection fluid to be injected into the tubing string inaccordance with a second valve configuration, wherein each of the firstvalve configuration is defined by a condition of the valves in whicheach valve in the plurality of valves is in either the fully openposition or the fully closed position.

In some examples, the individual control units are selectively isolatedin an isolation sequence.

In some examples, the isolation sequence is from a toe to a heel of thehydrocarbon well.

In some examples, each control unit has a respective circuitinterrupting device, wherein the power-line comprises a main power-lineand a plurality of branch power-lines connected to the main power-line,wherein the control units for the valves are connected to a respectivebranch power-line.

In some examples, wherein each circuit interrupting device comprises:first circuit interrupting device located in a main power-line tointerrupt current in the main power-line when an amperage threshold isexceeded; and a second circuit interrupting device located in arespective branch line from the main power-line connected to a powersupply of a respective control unit of a respective valve to interruptcurrent in the respective branch line when an amperage threshold isexceeded.

In some examples, the amperage thresholds of the first circuitinterrupting device and second circuit interrupting device of eachcircuit interrupting device decreases in a descending order from a heelof the hydrocarbon well to a toe of the hydrocarbon well.

In accordance with another embodiment of the present disclosure, thereis provided a controller for controlling control units of a tubingstring located in a hydrocarbon well, the tubing string having aplurality of valves, each valve having a control unit, each control unitbeing connected in series to a power-line providing power andcommunication, each of the control units being independentlycontrollable, the controller comprising: a processor; and a memorycoupled the at least one processor, the memory having tangibly storedthereon executable instructions for execution by the processor that,when executed by the processor, cause the controller to: detect a shortcircuit, fault or failure in one of the control units of the tubingstring via an output of the power-line; cause individual control unitsto be isolated from the power-line via a circuit interrupting device;and determine one or more control units is associated with the shortcircuit, fault or failure via the output of the power-line whileindividual control units are isolated from the power-line.

In accordance with a further embodiment of the present disclosure, thereis provided a downhole fault protection system for a tubing stringlocated in a hydrocarbon well, the tubing string having a plurality ofvalves, each valve having a control unit, each control unit beingconnected in series to a power-line providing power and communication,each of the control units being independently controllable, the systemcomprising: a main power-line having a plurality of branch linesconnected thereto; a control unit for a valve connected to each of thebranch lines; a line protection circuit for each of the control units,each line protection circuit comprising a pair of circuit interruptingdevices, a first circuit interrupting device in each pair located in themain power-line to interrupt current in the main power-line when anamperage threshold is exceeded and a second circuit interrupting devicein each pair located in a respective branch line from the mainpower-line that extends to a power supply of a respective control unitof a respective valve to interrupt current in the respective branch linewhen an amperage threshold is exceeded; wherein the amperage thresholdsof the first and second circuit interrupting devices decreases in adescending order from a heel of the hydrocarbon well to a toe of thehydrocarbon well, enabling valves to be selectively isolated in orderfrom the toe to the heel by increasing a current applied to the lineprotection circuits.

In some examples, the difference in amperage thresholds between adjacentpair of circuit interrupting devices is 50-200 mA, preferably 100-150mA, and more preferably 100-110 mA.

In some examples, the line protection circuit further comprises a NTC(Negative temperature coefficient) thermistor adjacent to the firstcircuit interrupting device in the main power-line, wherein the NTCthermistor of the line protection circuits are matched such that theoperating temperatures of the first circuit interrupting devices differby less than a threshold amount.

In some examples, the first and circuit interrupting devices are fuses.

In accordance with yet a further embodiment of the present disclosure,there is provided a downhole fault protection system for multiple stagesof downhole valves in a well, comprising: a main power-line having aplurality of branch lines connected thereto; a control unit for a valveconnected to each of the branch lines; a line protection circuit foreach of the control units, each line protection circuit comprising acircuit interrupting device for isolating the valve from the mainpower-line when an amperage threshold at the control unit is exceeded;wherein the amperage thresholds of the circuit interrupting devicesdecreases in a descending order from a heel of the hydrocarbon well to atoe of the hydrocarbon well, enabling valves to be selectively isolatedin order from the toe to the heel by increasing a current applied to theline protection circuits.

In accordance with yet a further embodiment of the present disclosure,there is provided a downhole fault protection system comprising a seriesof paired circuit interrupting devices, a first circuit interruptingdevice in each pair located in a main power-line to interrupt current inthe main power-line when an amperage threshold is exceeded and a secondcircuit interrupting device in each pair located in a respective branchline from the main power-line that extends to a power supply of arespective control unit of a respective flow communication station tointerrupt current in the respective branch line when an amperagethreshold is exceeded, wherein the amperage thresholds of the circuitinterrupting devices decreases in a descending order from a heel of theinjection well to a toe of the injection well. When a short circuit,control unit fault or control unit failure occurs, the current in themain power-line can be steadily increased to sequentially trigger/blowthe paired fuses from the toe to the heel of the injection well untilthe control unit having the short circuit, control unit fault or controlunit failure is disconnected, and the operability of the injection wellis restored.

In accordance with a further aspect of the present disclosure, there isprovided a controller configured to perform the methods describedherein. In some embodiments, the controller comprises at least oneprocessor and a memory coupled the at least one processor, the memoryhaving tangibly stored thereon executable instructions for execution bythe at least one processor that, when executed by the at least oneprocessor, cause the controller to perform at least parts of the methodsdescribed herein.

In accordance with yet a further aspect of the present disclosure, thereis provided a non-transitory machine readable medium having tangiblystored thereon executable instructions for execution by at least oneprocessor of a controller, wherein the executable instructions, whenexecuted by the at least one processor, cause the controller to performat least parts of the methods described herein.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic diagram of a first example apparatus with whichexample embodiments of the present disclosure may be applied.

FIG. 2 is a schematic diagram of an injection string of the apparatus ofFIG. 1 in accordance with an example embodiment of the presentdisclosure.

FIG. 3 is a schematic diagram of a valve for use in the injection stringof FIG. 2 with the valve in a closed condition in accordance with anexample embodiment of the present disclosure.

FIG. 4 is a schematic diagram of a valve for use in the injection stringof FIG. 2 with the flow communicator in an open condition in accordancewith an example embodiment of the present disclosure.

FIG. 5 is a schematic diagram of the valve of FIGS. 2 and 3 showing theflow communication between a bi-directional pump, first and secondworking fluid-containing spaces, and a working fluid supply compensatorof the valve in accordance with an example embodiment of the presentdisclosure.

FIG. 6 is a schematic diagram of a system for operating hydrocarbonwells in accordance with an example embodiment of the presentdisclosure.

FIG. 7 is a block diagram of a programmable logical controller of thesystem of FIG. 6 in accordance with an example embodiment of the presentdisclosure.

FIG. 8 is a schematic illustration of an example injection well withwhich example embodiments of the present disclosure may be applied.

FIG. 9 is a block diagram of a control unit of a flow communicationstation in accordance with one example embodiment of the presentdisclosure.

FIG. 10 is a block diagram showing a motor controller and sensorinterface of the control unit of FIG. 9 in accordance with one exampleembodiment of the present disclosure.

FIG. 11 is a schematic diagram showing a driver circuit of the motorcontroller and sensor interface of FIG. 10.

FIG. 12 is a switching diagram for the driver circuit of FIG. 11.

FIG. 13 is a general circuit diagram showing the topography of the powersupply of the control unit of FIG. 9.

FIG. 14 is a general circuit diagram showing a line protection circuitof the control unit of FIG. 9.

FIG. 15 is a flowchart of a method of fault detection and recovery in atubing string located in a hydrocarbon well in accordance with oneexample embodiment of the present disclosure.

FIG. 16 is a flowchart of a method of downhole fault protection inaccordance with one example embodiment of the present disclosure.

DESCRIPTION OF EXAMPLE EMBODIMENTS

The present disclosure is made with reference to the accompanyingdrawings, in which embodiments are shown. However, many differentembodiments may be used, and thus the description should not beconstrued as limited to the embodiments set forth herein. Rather, theseembodiments are provided so that this disclosure will be thorough andcomplete. Wherever possible, the same reference numbers are used in thedrawings and the following description to refer to the same elements,and prime notation is used to indicate similar elements, operations orsteps in alternative embodiments. Separate boxes or illustratedseparation of functional elements of illustrated systems and devicesdoes not necessarily require physical separation of such functions, ascommunication between such elements may occur by way of messaging,function calls, shared memory space, and so on, without any suchphysical separation. As such, functions need not be implemented inphysically or logically separated platforms, although they areillustrated separately for ease of explanation herein. Different devicesmay have different designs, such that although some devices implementsome functions in fixed function hardware, other devices may implementsuch functions in a programmable processor with code obtained from amachine-readable medium. Lastly, elements referred to in the singularmay be plural and vice versa, except where indicated otherwise eitherexplicitly or inherently by context.

System for Operating Hydrocarbon Wells

Reference is first made to FIG. 6 which illustrates a system 600 foroperating hydrocarbon wells, e.g. oil wells 601, in accordance with oneembodiment of the present disclosure. The system 600 may be used tooperate one or more oil wells 601 in the same or different hydrocarbonreservoirs (e.g., petroleum or oil and gas reservoirs). The oil wells601 may comprise injection wells, production wells, or a combinationthereof. The system 600 comprises a number of control systems 602 (onlyone of which is shown in FIG. 6). Each control system 602 may controlmultiple wells 601 or a single well 601. The control systems 602 arelocated at the site of the respective wells 601. The control systems 602comprise a supervisory control and data acquisition (SCADA) controlsystem 604 coupled to a controller, such as a programmable logiccontroller (PLC) 606. A human machine interface (HMI) 608 is coupled tothe SCADA control system 604. The HMI 608 typically comprises a visualinterface provided by a display that provides a graphical user interface(GUI) that displays operating data and information about the respectivewell 601, and an input interface for receiving user input provided byone or more input devices such as keyboard and mouse. The HMI 608 mayoptionally comprise a microphone and a speaker, for example, for speechrecognition.

The PLC 606 is coupled to downhole sensors 640 and downhole actuators650 coupled to a respective valve (not shown) in a plurality of valvesof a tubing string installed in the oil well 200. The tubing string maybe any suitable type of tubing string including, but not limited to, aninjection string, a production string or a lift gas conduit among otherpossibilities. The downhole sensors 640 sense one or more conditions ata respective valve. The downhole sensors 640 may comprise at least onepressure sensor 642 for each valve in the tubing string and optionallyat least one temperature sensor for each valve in the tubing string. ThePLC 606 is typically coupled to the downhole sensors 640 and thedownhole actuators 650 via a wired communication path. The downholeactuators 650 are electronically controlled and may be actuated to openor close the respective valves many times.

The PLC 606 may also be coupled to a fluid actuator 620 located at thesurface, such as a surface pump when the injection fluid is a liquidsuch as water or a compressor when the injection fluid is a gas, whenthe PLC 606 controls an injection well to maintain pressure, or cause adisplacement process, in a hydrocarbon reservoir in a subterraneanformation. The displacement process may be a secondary recovery process,such as waterflood, gas lift, natural gas flood or immiscible gas flood,or an EOR process, such as enriched miscible natural gas flood, miscibleCO₂ flood, chemically enhanced water flood or water alternating gas(WAG) flood among other possibilities. The fluid actuator 620 may be apump, compressor and/or flow regulator depending on the type ofinjection fluid being used, coupled to a fluid supply 630 located at thesurface. The injection fluid may be water or a liquid that comprisessubstantially of water or compressed gas, such as CO₂, among otherpossibilities. The PLC 606 is also coupled to sensors 622 located at thesurface that senses one or more parameters (or characteristics) of afluid supplied to the respective well 601. The surface sensors 622comprise a surface flowmeter 624 that measures a flow rate of aninjection fluid and a pressure sensor 624 that measures a pressure ofthe injection fluid.

An additive supply and/or treatment supply (not shown) may also beprovided. The additive supply and/or treatment supply may be connectedto the PLC 606 and provides a source of a compound or composition thatmay be used with the injection fluid or instead of the injection fluidincluding, but not limited to one or more of, water, low salinity water,a dry gas, solvent, miscible gas, tracer, proppant, blocking agent,relative permeability modifying agent, surfactant, nanoparticulate orother additive which may be absorbed into the formation/reservoir. Theadditive supply and/or treatment supply may be connected to a mixerwhich is connected to the fluid supply 630 for mixing the compound orcomposition with the injection fluid, or may be connected directly tothe fluid actuator 620 for directly injecting the compound orcomposition.

The PLC 606 may communicate with an application server 616 via a wiredor wireless (e.g., cellular, Wi-Fi®, etc.) communication path, and withone or more databases 618 via the data server 616. The applicationserver 616 may provide control information, such as optimizationinformation, for operating the wells 601, namely for controlling thevalves of the tubing string. The PLC 606 stores sensor data and deriveddata and information, such as injection data (e.g., flow rates and/orvolumes) and/or production data (e.g., flow rates and/or volumes),relating to the operation of the respective wells 601. The PLC 606communicates such data and information to the application server 616,which may store the data and information in the databases 618 ashistorical data for each of the wells 601. The historical data maycomprise sensor data, operating settings or parameters such as valveposition data relating to the open or closed state of the valves of thetubing string (e.g., a state of the tubing string or well 601), andderived data and information, such as production data over time (e.g., atime log). The data and information may comprise a time log of pressuredata, temperature data, valve position/state (i.e., open or closed), andpossibly derived flow rate or volume through each valve and/or possiblyan interval specific reservoir characterization.

The SCADA control system 604 is typically used to communicate to or withan operator of the well 601. The system 600 is operated by the PLC 606and/or the application server 616. The PLC 606 communicates with andprovides the SCADA control system 604 with data and information relatingto the operation of the respective wells 601. Typically, only a subsetof the data and information of the PLC 606 is provided to the SCADAcontrol system 604, such as a time filtered sample of one or moreelements of the data and information mentioned above. The SCADA controlsystem 604 may communicate with a data server 612 via a wired orwireless (e.g., cellular, Wi-Fi® etc.) communication path, and with oneor more databases 614 via the data server 612. The SCADA control system604 may provide the data server 612 with data and information, relatingto the operation of the respective wells 601, which may store the dataand information in the databases 614 as historical data for each of thewells 601.

Reference is next made to FIG. 7 which illustrates the components of acontroller, such as PLC 606, of the system 600 of FIG. 6 in accordancewith one example embodiment of the present disclosure. The PLC 606comprises at least one processor 702 (such as a microprocessor) whichcontrols the overall operation of the PLC 606. The processor 702 iscoupled to a plurality of components via a communication bus (not shown)which provides a communication path between the components and theprocessor 702.

The processor 702 is coupled to RAM 722, ROM 724, persistent(non-volatile) memory 726 such as flash memory, and a communicationmodule 728 for communication with the surface fluid actuator 620,surface sensors 622, downhole sensors 640 and downhole actuators 650.The processor 702 is also coupled to one or more data ports 744 such asserial data ports for data I/O (e.g., USB data ports), and a powersupply 750.

The communication module 728 provides wired and/or wirelesscommunication capabilities for communicating with an application server616, surface fluid actuator 620, surface sensors 622, downhole sensors640 and downhole actuators 650. Typically the communication module 728is coupled to the downhole sensors 640 and downhole actuators 650 via awired connection, such as a shared power and data line given spaceconstraints and interference problems. The communication module 728 maycomprise a wireless transceiver allowing the PLC 606 to communicate viaone or any combination of cellular, Wi-Fi®, Bluetooth® or othershort-range wireless communication protocol such as NFC, IEEE 802.15.7a(also referred to as UltraWideband (UVEB)), Z-Wave, ZigBee, ANT/ANT+ orinfrared (e.g., Infrared Data Association (IrDA)). The PLC 606 may usethe communication module 728 to access the application server 616 viaone or more communications networks, such as the Internet. Theapplication server 616 may be located behind a firewall (not shown).

Operating system software 752 executed by the processor 702 is stored inthe persistent memory 726 but may be stored in other types of memorydevices, such as ROM 724 or similar storage element. A number ofapplications 756 executable by the processor 702 are also stored in thepersistent memory 726 including a production control application 760,which may operate the respective well 601 in accordance with optimizedoperating settings or parameters based on sensor data acquired from therespective well 601 and determined by an optimization application 762 ofthe application server 616 and pushed down to the PLC 606.Alternatively, the optimization application may be installed and run bythe PLC 606. The optimization application may be a machine learning orartificial intelligence based application. The memory 726 also stores avariety of data 770 including sensor data 772 acquired by the surfacesensors 622 and downhole sensors 640, operating settings 774 such asoptimized operating settings or parameters including, but not limited tovalve position data relating to the open or closed state of the valvesof the tubing string (e.g., a state of the tubing string or well 601),and production data 776.

System software, software modules, specific device applications, orparts thereof, may be temporarily loaded into a volatile store, such asRAM 722, which is used for storing runtime data variables and othertypes of data or information. Communication signals received by the PLC606 may also be stored in RAM 722. Although specific functions aredescribed for various types of memory, this is merely one example, and adifferent assignment of functions to types of memory may be used inother embodiments.

FIG. 8 is a schematic illustration of an example horizontal injectionwell having a tubing string, i.e. an injection string 800, installedtherein with which example embodiments of the present disclosure may beapplied. The injection string 800 comprises a plurality of flowcommunication stations (or also known as valves). In the example of FIG.8, the injection string 800 has 8 valves. However, any number of valvesmay be present. Each of the valves 802 is equipped with at least onepressure sensor for measuring a pressure of the formation in which theinjection string 800 is located, denoted p₁, p₂ . . . p₈, at thelocation of the respective valve 802. Each valve has an actuator 650adapted to change a position or the state of respective valve 802, fromeither open or closed. Each of the valves 802 may be separately openedor closed. The surface sensors 622 comprise a surface flowmeter thatmeasures the flow rate of an injection fluid at the surface and pressuresensor that measures a pressure of the injection fluid at the surface.An operating state of the well 601 is a valve configuration in which atleast one of the valves 802 is disposed in the fully open position. Forn valves 802, there are 2^(n)−1 operating states (i.e., 2^(n) totalstates less the non-operating state in which all valves 802 are disposedin the fully closed position. The particular valves 802 that aredisposed in the fully opened position and fully closed position isunique to each operating state of the well 601.

The controllable input parameters of the PLC 606 are the flow rate ofthe injection fluid at the surface, denoted I, the pressure of theinjection fluid at the surface, denoted P, and the position or the stateof valves 80, denoted s₁, s₂ . . . s₈. The condition (also referred tostate or positon) of each valve is either fully open or fully closed.The measurable parameters are the pressure of the injection fluid at thesurface (e.g., at the surface pump), the flow rate of the pressure ofthe injection fluid at the surface (e.g., at the surface pump), and thepressures at the location of each valve 802 (e.g., in proximity of eachvalve 802). Each valve 802 is sometimes referred to a stage of thetubing string, e.g. injection string 800.

Example Tubing String for Injection Well

Referring to FIG. 1, there is provided a hydrocarbon producing system100 including an injection well 104 and a production well 106. Theinjection well 104 includes a wellbore 104A for injecting an injectionfluid from the surface 102 and into the subterranean formation 101. Theproduction well 106 includes a wellbore 106A for receiving hydrocarbonmaterial that is displaced and driven by the injection fluid, andconducting the received hydrocarbon material to the surface. In someembodiments, the injection fluid is water or at least a substantialfraction of the injection fluid is water. In other embodiments, theinjection fluid is a gas such as, for example, enriched field gas orcarbon dioxide.

Each one of the wellbores 104A, 106A, independently, may be straight,curved, or branched and may have various wellbore sections. A wellboresection is an axial length of a wellbore. A wellbore section may becharacterized as vertical or horizontal even though the actual axialorientation may vary from true vertical or true horizontal, and eventhough the axial path may tend to corkscrew or otherwise vary. The termhorizontal, when used to describe a wellbore section, refers to ahorizontal or highly deviated wellbore section as understood in the art,such as, for example, a wellbore section having a longitudinal axis thatis between 70 and 110 degrees from vertical.

Referring to FIG. 2, the injection of the injection fluid from thesurface 102 to the subterranean formation 101, via the injection well104, is effected via one or more flow communication stations (five (5)flow communications 110A-E are illustrated). Successive flowcommunication stations may be spaced from each other along the wellboresuch that each one of the flow communication stations 110A-E,independently, is positioned adjacent a zone or interval of thesubterranean formation 101 for effecting flow communication between thewellbore 104A and the zone (or interval).

The injection fluid is injected through the wellbore 104A of theinjection well 104 via an injection conduit 200, such as an injectionstring including an injection string passage 200A. The injection string200 is disposed within the injection well 104. The injection fluid isinjected from the injection string 200 into the wellbore 104A.

For effecting the flow communication between the injection string 200and the wellbore 104A, at each one of the flow communication stations110A-E, independently, the injection string 200 includes a respectiveflow control apparatus (valve) 202. The valve 202 includes a flowcommunicator 204 through which the injection of the injection fluid,into the wellbore, is effectible. The valve 202 is configured forintegration within the injection string 200. The integration may beeffected, for example, by way of threading or welding.

The valve 202 includes a flow control member 208. The flow controlmember 208 is configured for controlling the conducting of material bythe valve 202 via the injection string flow communicator 204. The flowcontrol member 208 is displaceable relative to the injection string flowcommunicator 204 for effecting opening of the injection string flowcommunicator 204. In some embodiments, for example, the flow controlmember 208 is also displaceable, relative to the injection string flowcommunicator 204, for effecting closing of the injection string flowcommunicator 204. In this respect, the flow control member 208 isdisplaceable from a closed position to an open position. The openposition corresponds to an open condition of the injection string flowcommunicator 204. The closed position corresponds to a closed conditionof the injection string flow communicator 204. For each one of the flowcommunication stations 110A-E, independently, an open condition of theflow communication station corresponds to the open condition of therespective injection string flow communicator 204. For each one of theflow communication stations 110A-E, independently, a closed condition ofthe flow communication station corresponds to the closed condition ofthe respective injection string flow communicator 204

In the closed position, the injection string flow communicator 204 iscovered by the flow control member 208, and the displacement of the flowcontrol member 208 to the open position effects at least a partialuncovering of the flow communicator 204 such that the flow communicator204 becomes disposed in the open condition. In some embodiments, forexample, in the closed position, the flow control member 208 isdisposed, relative to the injection string flow communicator 204, suchthat a sealed interface is disposed between the injection string passage200A and the wellbore 104A, and the disposition of the sealed interfaceis such that the conduction of the injection fluid between the injectionstring passage 200A and the wellbore 104A, via the injection string flowcommunicator 204 is prevented, or substantially prevented, anddisplacement of the flow control member 208 to the open position effectsflow communication, via the injection string flow communicator 204,between the injection string passage 200A and the subterranean formation101, such that the conducting of the injection fluid from the injectionstring passage 200A and the wellbore 104A, via the injection string flowcommunicator 204, is enabled.

In some embodiments, for example, the flow control member 208 isdisplaceable by a shifting tool. In some embodiments, for example, theflow control member is displaceable in response to receiving of anactuation signal (such as, for example, by actuation by a hydraulicpump).

In some embodiments, for example, the injection well 104 includes acased-hole completion. In such embodiments, the wellbore 104A is linedwith casing 300.

A cased-hole completion involves running casing 300 down into thewellbore 104A through the production zone. The casing 300 at leastcontributes to the stabilization of the subterranean formation 101 afterthe wellbore 104A has been completed, by at least contributing to theprevention of the collapse of the subterranean formation 101 that isdefining the wellbore 101. In some embodiments, for example, the casing300 includes one or more successively deployed concentric casingstrings, each one of which is positioned within the wellbore 104A,having one end extending from the wellhead 12. In this respect, thecasing strings are typically run back up to the surface. In someembodiments, for example, each casing string includes a plurality ofjointed segments of pipe. The jointed segments of pipe typically havethreaded connections.

In some embodiments, for example, it is desirable to seal an annulus,formed within the wellbore, between the casing string and thesubterranean formation. Sealing of the annulus is desirable formitigating versus conduction of the fluid, being injected into thesubterranean formation, into remote zones of the subterranean formationand thereby providing greater assurance that the injected fluid isdirected to the intended zone of the subterranean formation.

To prevent, or at least interfere, with conduction of the injected fluidthrough the annulus, and, perhaps, to an unintended zone of thesubterranean formation that is desired to be isolated from the formationfluid, or, perhaps, to the surface, the annulus is filled with a zonalisolation material. In some embodiments, for example, the zonalisolation material includes cement, and, in such cases, duringinstallation of the assembly within the wellbore, the casing string iscemented to the subterranean formation 101, and the resulting system isreferred to as a cemented completion.

In some embodiments, for example, the zonal isolation material isdisposed as a sheath within an annular region between the casing 300 andthe subterranean formation 101. In some embodiments, for example, thezonal isolation material is bonded to both of the casing 300 and thesubterranean formation 101. In some embodiments, for example, the zonalisolation material also provides one or more of the following functions:(a) strengthens and reinforces the structural integrity of the wellbore,(b) prevents, or substantially prevents, produced formation fluids ofone zone from being diluted by water from other zones, (c) mitigatescorrosion of the casing 300, and (d) at least contributes to the supportof the casing 300.

In those embodiments where the injection well 104 includes a casedcompletion, in some of these embodiments, for example, the casingincludes the plurality of casing flow communicators 304A-E, and for eachone of the flow communication stations 110A-E, independently, the flowcommunication between the wellbore 104A and the subterranean formation101, for effecting the injection of the injection fluid, is effectedthrough the respective one of the casing flow communicators 304A-E. Insome embodiments, for example, each one of the casing flow communicators304A-E, independently, is defined by one or more openings 301. In someembodiments, for example, the openings are defined by one or more portsthat are disposed within a sub that has been integrated within thecasing string 300, and are pre-existing, in that the ports exist beforethe sub, along with the casing string 300, has been installed downholewithin the wellbore 104A. Referring to FIG. 2, in some embodiments, forexample, the openings are defined by perforations 301 within the casingstring 300, and the perforations are created after the casing string 300has been installed within the wellbore 104A, such as by a perforatinggun. In some embodiments, for example, for each one of the flowcommunication stations 110A-E, independently, the respective one of thecasing flow communicator 304A-E is disposed in alignment, or substantialalignment, with the injection string flow communicator 204 of therespective one of the flow communication stations 110A-E

In this respect, in those embodiments where the injection well 104includes a cased completion, in some of these embodiments, for example,for each one of the flow communication stations 110A-E, independently,flow communication, via the flow communication station, is effectiblebetween the surface 102 and the subterranean formation 101 via theinjection string 104, the respective injection string flow communicator204, the annular space 104B within the wellbore 104A between theinjection string 200 and the casing string 300, and the respective oneof the casing string flow communicators 304A-E.

In some embodiments, for example, while injecting injection fluid intothe subterranean formation 101 via a one of the flow communicationstations 110A-E (the stimulation-effecting flow communication station),for each one of the adjacent flow communication stations, independently,a sealed interface is disposed within the wellbore 104A-E forpreventing, or substantially preventing, flow communication, via thewellbore, between the stimulation-effecting flow communication stationand the adjacent flow communication station. In this respect, withrespect to the embodiment illustrated in FIG. 1, sealed interfaces108A-D are provided. In some embodiments, for example, the sealedinterface is established by a packer. In those embodiments where thecompletion is a cased completion, in some of these embodiments, forexample, the sealed interface extends across the annular space betweenthe injection string 200 and the casing string 300.

In some embodiments, for example, with respect to the flow communicationstation that is disposed furthest downhole (i.e. flow communicationstation 110E), a further sealed interface 108E is disposed within thewellbore 104A for preventing, or substantially preventing, flowcommunication between the flow communication station 110E and adownhole-disposed portion 104AA of the wellbore 104A.

Referring to FIGS. 2 and 3, in some embodiments, for example, the valve202 includes a housing 203. The housing 203 contains a fluid conductor205 and a valve subassembly 230. The fluid conductor 205 includes afluid passage housing 203A that defines a fluid passage 210 foreffecting conduction of the injection fluid through the valve 202 whilethe valve 202 is integrated within the injection string 200. In thisrespect, the fluid passage 210 forms part of the injection stringpassage 200A.

The valve subassembly 230 is provided for controlling flow communicationbetween the fluid passage 210 and the subterranean formation 101. Inthis respect, the valve subassembly 230 includes a valve subassemblyhousing 203B that contains the flow communicator 204 and the flowcontrol member 208. The housing 203B is mounted to the housing 203A.

The flow communicator 204 effects flow communication between the fluidpassage 210 and the subterranean formation 101. The flow communicator204 includes one or more ports 212 defined within an outermost surfaceof the housing 203 (such as, for example, a manifold of the housing203B). In this respect, the flow communication between the fluid passage210 and the subterranean formation 101 is effectible via the one or moreports 212. The injection string flow communicator 204 further includesan orifice 216 disposed within a space 222 (e.g. a passage) between thefluid passage 210 and the one or more ports 212, such that flowcommunication between the fluid passage 210 and the one or more ports212 (and, therefore, the subterranean formation 101) is effectible viathe orifice 216.

The orifice 216 is defined within a valve seat 218. In some embodiments,for example, the valve seat 218 is defined within a manifold of thehousing 203B. The valve seat 218 is configured for receiving seating ofthe flow control member 208 (such that the flow control member 208becomes disposed in the closed position) for effecting disposition ofthe injection string flow communicator 204 in the closed condition.Referring to FIG. 4, while the flow control member 208 is spaced apartfrom the valve seat 218, the flow control member 208 is disposed in theopen position, and, correspondingly, flow communication is establishedbetween the fluid passage 210 and the one or more ports 212 via theorifice 216, such that the injection string flow communicator 204 isdisposed in the open condition. In some embodiments, for example, theflow control member 208 includes a seat-engaging surface 208A forseating on a seating surface 218A defined by the valve seat 218 (FIG.3), such that the flow communicator 204 becomes disposed in the closedcondition. In some embodiments, for example, the material of the seatengaging surface 208A is nickel aluminum bronze and the material of theseating surface 218A is QPQ-nitrided 17-4PH stainless steel.

The orifice 216 has a central axis 216A, and the fluid passage 210defines a central longitudinal axis 210A. In some embodiments, forexample, the orifice 216 and the fluid passage 210 are co-operativelyconfigured such that, while the valve 202 is oriented such that thecentral axis 216A is disposed within a horizontal plane, the centrallongitudinal axis 210A is disposed at an acute angle of less than 45degrees relative to the horizontal plane, such as, for example, at anacute angle of less than 22.5 degrees relative to the horizontal plane,such as, for example at an acute angle of less than 10 degrees relativeto the horizontal plane. In some embodiments, for example, the orifice216 and the fluid passage 210 are co-operatively configured such that,while the valve 202 is oriented such that the central axis 216A isdisposed within a horizontal plane, the central longitudinal axis 210Ais parallel, or substantially parallel, to the horizontal plane.

In some embodiments, for example, the orifice 216 defines a central axis216A, and each one of the one or more ports 212, independently, define acentral axis 212A. In some embodiments, for example, the orifice 216 andthe one or more ports 212 are co-operatively configured such that, whilethe valve 202 is oriented such that the central axis 216A is disposedwithin a horizontal plane, the central axis 212A is disposed at an acuteangle of less than 45 degrees relative to the horizontal plane, such as,for example, at an acute angle of less than 22.5 degrees relative to thehorizontal plane, such as, for example at an acute angle of greater than10 degrees relative to the horizontal plane. In some embodiments, forexample, the orifice 216 and the one or more ports 212 areco-operatively configured such that, while the valve 202 is orientedsuch that the central axis 216A is disposed within a horizontal plane,the central axis 212A is parallel to the horizontal plane.

In some embodiments, for example, a tracer material source 224 isdisposed within the space 222. The tracer material source 224 isconfigured for releasing tracer material into injection fluid that isflowing past the tracer material source 224, while being injected intothe subterranean formation 101 via the injection string flowcommunicator 204, for monitoring by a sensor within the system 100 toprovide information about the process. By virtue of the above-describedco-operative orientation of the fluid passage 210, the orifice 216, andthe one or more of the ports 212, there is an opportunity to increasethe volume of the space 222 disposed between the fluid passage 210 andthe one or more ports 212 without impacting, or without at leastsignificantly impacting, on the space available within the apparatus 210for defining the fluid passage 210. In this respect, the space 222 couldbe made larger for accommodating a larger quantity of tracer material.

In some embodiments, for example, the valve subassembly 230 furtherincludes an actuator 232 for effecting displacement of the flow controlmember 208 relative to the valve seat 218. In some embodiments, forexample, the flow control member 208 is mounted to the actuator 232.

In some embodiments, for example, the actuator 232 is a linear actuator,and is disposed for movement along a linear axis, such that the flowcontrol member 208, correspondingly, is also disposed for movement alongthe linear axis. In some embodiments, for example, this axis of travelis parallel, or substantially parallel, to the central axis of theorifice 116 (and, in some embodiments, for example, the travel is alongan axis that is co-incident, or substantially co-incident, with thecentral axis 216A of the orifice 116).

In some embodiments, for example, seating of the flow control member 208relative to the valve seat 218 (FIG. 3) is effected by extension of thelinear actuator 232 towards the valve seat 218 to an extended position,and unseating of the flow control member 208 relative to the valve seat218 is effected by retraction of the linear actuator 232 relative to thevalve seat 218 to a retracted position. In some embodiments, forexample, the linear actuator 232 is configured to reciprocate betweenthe extended (FIG. 3) and retracted positions (FIG. 4).

In some embodiments, for example, the linear actuator 232 is a hydraulicactuator that includes working fluid and a piston 236, with the workingfluid being disposed in fluid pressure communication with the piston236. In some embodiments, for example, the working fluid is a hydraulicoil. Relatedly, the valve sub-assembly housing 203B is configured forcontaining the working fluid. The housing 203B, the working fluid, andthe piston 236 are co-operatively configured such that, in response topressurizing of the working fluid 236, an unbalanced force isestablished and exerted on the piston 236 for urging movement of thepiston 236, with effect that the flow control member 208 is displacedrelative to the valve seat 218. In some embodiments, for example, thehydraulic actuator 232 has a first mode of operation and a second modeof operation, and, in the first mode of operation, the establishment ofan unbalanced force is with effect that seating of the flow controlmember 208, relative to the valve seat 218, is effected (FIG. 3), and,in the second mode of operation, the establishment of an unbalancedforce is with effect that unseating of the flow control member 208,relative to the valve seat 218, is effected (FIG. 4). In someembodiments, for example, the hydraulic actuator 232 further includes abi-directional pump 240 which is operable in the first and second modesof operation in co-operation with a bi-directional motor 241 that iselectrically coupled, via a eight (8) pin connector 302, to a powersupply, extending externally, of the injection string 200, in the formof a power and communications cable 306. The valve 202 also comprises apressure sensor 642 coupled to a PLC 606 (FIG. 6) at the surface 102 viathe power and communications cable 306. Alternatively, the pressuresensor 642 may be coupled to the PLC 606 wirelessly via a wirelesstransmitter (not shown) of the valve 202.

In those embodiments where the hydraulic actuator 232 includes abi-directional pump 240, in some of these embodiments, for example, afirst working fluid-containing space 242 and a second workingfluid-containing space 244 are disposed within the housing 203B. Eachone of the spaces 242, 244, independently, is disposed in fluid pressurecommunication with the piston 236.

The housing 203B, the bidirectional pump 240, the first space 242, andthe second space 244 are co-operatively configured such that, while theflow control member 208 is seated relative to the valve seat 218, andthe bidirectional pump 240 becomes disposed in the first mode ofoperation, the bidirectional pump 240 is receiving supply of workingfluid from the first space 242 and discharging pressurized working fluidinto the second space 244, with effect that working fluid, within thesecond space 244, and in fluid pressure communication with the piston236, becomes disposed at a higher pressure than working fluid within thefirst space 242 and in fluid pressure communication with the piston 236,such that an unbalanced force is acting on the piston 236 and effectsretraction of the piston 236 relative to the valve seat 218, such thatthe flow control member 208 becomes unseated relative to the valve seat218 and thereby effecting flow communication between the fluid passage210 and the subterranean formation via the flow communicator 204.

The housing 203B, the bidirectional pump 240, the first space 242, andthe second space 244 are further co-operatively configured such that,while the flow control member 208 is unseated relative to the valve seat218, and the bidirectional pump 240 becomes disposed in the second modeof operation, the bidirectional pump 240 is receiving supply of workingfluid from the second space 244 and discharging pressurized workingfluid into the first space 242, with effect that working fluid, withinthe first space 242 and in fluid pressure communication with the piston236, becomes disposed at a higher pressure than working fluid within thesecond space and in fluid pressure communication with the piston, suchthat an unbalanced force is acting on the piston 236 and effectsextension of the piston 236 relative to the valve seat 218, such thatthe flow control member 208 becomes seated relative to the valve seat218, with effect that the flow communicator 204 becomes disposed in theclosed condition.

In some embodiments, for example, the first space 242 is disposed forfluid coupling with a working fluid supply compensator 260, in responseto the pressure of the working fluid within the first space 242 becomingdisposed below a minimum predetermined pressure. Similarly, in someembodiments, for example, the second space 244 is disposed for fluidcoupling with a working fluid supply compensator 260, in response to thepressure of the working fluid within the second space 244 becomingdisposed below a minimum predetermined pressure. This is to ensure thatworking fluid is being supplied from the discharge of the pump 240 at asufficient pressure for acting on the piston 236 and overcoming theforce applied by the injection fluid within the space 222 for resistingmovement of the piston 236, and thereby effecting extension andretraction of the piston 236.

The working fluid supply compensator 260 includes working fluid disposedat a pressure of at least the pressure of the injection fluid disposedwithin the fluid passage 210. In this respect, the working fluid withinthe working fluid supply compensator 260 is disposed in fluid pressurecommunication with the injection fluid disposed within the fluid passage210, such as via a moveable piston 262 that is sealingly disposed withinthe working fluid supply compensator 260. In some embodiments, forexample, the pressure of the injection fluid disposed within the fluidpassage 210 is between 0 psig and 10,000 psig.

The injection fluid is communicated from the fluid passage 210 via aport 205 disposed within the housing 203A, such that the working fluidwithin the working fluid supply compensator 260 is disposed at the same,or substantially the same, pressure as the injection fluid within thefluid passage 210. In some embodiments, for example, a resilient member,such as spring 266, is disposed within the compensator 260 and biasesthe piston 262 towards the working fluid for creating a pre-load on theworking fluid, and this is useful during start-up to prevent cavitation.In this respect, the pressure of the working fluid is equivalent toabout the sum of the pressure of the injection fluid within the fluidpassage 210 and that attributable to the spring force.

Referring to FIG. 5, a one-way valve 2602 (such as, for example, a checkvalve) is provided for controlling flow communication with the workingfluid supply compensator 260, and is configured for opening in responseto the pressure of the working fluid within the first space 242 becomingdisposed below the pressure of the working fluid within the workingfluid compensator 260. Similarly, a one-way valve 2604 (such as, forexample, a check valve) is provided for controlling flow communicationwith the working fluid supply compensator 260, and is configured foropening in response to the pressure of the working fluid within thesecond space 244 becoming disposed below the pressure of the workingfluid within the working fluid compensator 260.

Again referring to FIG. 5, the bi-directional hydraulic pump 240includes a first fluid passage 2402 that is disposed in flowcommunication with the first space 242, and a second fluid passage 2404that is disposed in flow communication with the second space 244. Thefirst fluid passage 2402 is disposed in flow communication with a valve2406 (such as, for example, a relief valve) configured for opening inresponse to the pressure differential between the first fluid passage2402 and the working fluid supply compensator 260 becoming disposedabove a predetermined maximum pressure differential (such as, forexample, 5500 psig), with effect that working fluid from within thefirst space 242 is conducted to the working fluid supply communicator260 for accumulation within the working fluid supply communicator 260.Similarly, the second fluid passage 2404 is disposed in flowcommunication with a valve 2408 (such as, for example, a relief valve)configured for opening in response to the pressure differential betweenthe second fluid passage 2404 and the working fluid supply communicator260 becoming disposed above a predetermined maximum pressuredifferential (such as, for example, 5500 psig), with effect that workingfluid from within the second space 242 is conducted to the working fluidsupply communicator 260 for accumulation within the working fluid supplycommunicator 260. By virtue of this configuration, fluid pressure withinthe first and second spaces 242, 244 may be sufficiently reduced forestablishing the necessary force imbalance to effect actuation of thepiston 236.

Referring again to FIGS. 2 and 3, in some embodiments, for example, apassage 244A extends through the piston 236 and joins two portions 244B,244C of the space 244. In this respect, the piston 236, the space 244B,and the space 244C are co-operatively configured such that joinder ofthe spaces 244B, 244C is maintained while the piston 236 is displacedbetween the extended and retracted positions. By configuring the secondspace 244 in this manner, fluid communication between the space 242 andthe hydraulic pump 240 is effected on the same side of the hydraulicpump 240 as is fluid communication between the space 244 and thehydraulic pump 240. In this respect, space within the housing 203,occupied by the first and second spaces 242, 244, is minimized, therebyenabling more of the space within the housing 203 to be dedicated forthe fluid passage 210.

In some embodiments, for example, the space 244C is defined by a chamber2441 that is disposed within the housing 203B, between an enlargedpiston portion 236B of the piston 236 and the orifice 218. Relatedly, aportion 242A of the first space 242 is defined by a chamber 2421 that isdisposed within the housing 203B and is also disposed, relative to thechamber 2441, on an opposite side of the enlarged piston portion 236B,between the enlarged piston portion 236B and a union 238A. Working fluidwithin chamber 2441 is urging displacement of the enlarged pistonportion 236B remotely relative to the orifice 216, and thereby urgingthe flow control member 108 towards an unseated position. Working fluidwithin chamber 2421 is urging displacement of the enlarged pistonportion 236B towards the orifice 216, and thereby urging the flowcontrol member 108 towards a seated position.

Displacement of the enlarged piston portion 236B, remotely relative tothe orifice 216, is limited by the union 238A, which, in this respect,functions as a piston retraction-limiting stop. Relatedly, displacementof the enlarged piston portion 236B, towards the orifice, is limited bythe valve seat 218. In some embodiments, for example, while beingdisplaced during the retraction and extension of the piston 236, theenlarged piston portion 236B is sealingly disposed within the housing203B, thereby preventing, or substantially preventing, conduction ofworking fluid between the chambers 2421 and 2441 via space between thehousing 203B and the enlarged piston portion 236B.

The union 238A forms part of the housing 203B. The union 238A isdisposed between the hydraulic pump 240 and the chamber 2421 (and,therefore, also the chamber 2441). In some embodiments, for example, thehydraulic pump 240 is threadably coupled to the union 238A.

A passage 242B extends through the union 238A such that the space 242extends from the space 242A defined by the chamber 2421 to the hydraulicpump 240, via the passage 242B.

In some embodiments, for example, a cutting tool 250 is mounted to thepiston 236 for translation with the flow control member 208 while theflow control member 208 is being displaced between the seated and theunseated positions. The flow control member 208 and the cutting tool 250are co-operatively configured such that, while the flow control member208 is seated relative to the valve seat 218, the cutting tool 250extends into a space 223 disposed between the orifice 216 and the one ormore ports 212. In some embodiments, for example, the flow controlmember 208 and the cutting tool 250 are also co-operatively configuredsuch that, while the flow control member 208 is unseated relative to thevalve seat 218, at least a portion of the cutting tool 250 is retractedfrom the space 223.

In some embodiments, for example, the flow control member 208, the valveseat 218, the orifice, the space 223 extending from the orifice 216 tothe one or more ports, and the cutting tool are co-operativelyconfigured such that, while the flow control member 208 is unseatedrelative to the valve seat 218, and the cutting tool 250 is disposedwithin the space 223 (e.g. a passage), the cutting tool 250 occupiesless than about 70% of the cross-sectional area of the space 223, suchas, for example, less than about 60% of cross-sectional area of thespace 223.

The flow control member 208 and the cutting tool 250 are furtherco-operatively configured such that, while: (i) the flow control member208 is being displaced relative to the valve seat 218 between the seatedand the unseated positions, and (ii) solid debris is disposed within thespace 223 (such as, for example, by way of ingress from the subterraneanformation 101 via the one or more ports 202, or, such as, for example,by way of precipitation from the injection fluid, or both), the cuttingtool 250 effects size reduction of the solid debris (such as, forexample, by way of comminution, such as, for example, by way ofcrushing, grinding, or cutting), such that size-reduced solid debris isobtained. By effecting such size reduction, obstruction of flowcommunication between the fluid passage 210 and the injection stringflow communicator 204 is mitigated. As well, by effecting such sizereduction, obstruction of mechanical components of the valve apparatus202, by such solid debris, is mitigated.

In some embodiments, for example, the flow control member 208 and thecutting tool 250 are further co-operatively configured such that, whilethe flow control member 208 is being retracted relative to the valveseat 218 (i.e. from the seated position), the size-reduced solid debrisis urged into the fluid passage 210 via a port 211, that is fluidlycoupled to the orifice 216 with a fluid passage 215, defined within thehousing 203B, such that the port 211 effects flow communication betweenthe fluid passage 210 and the orifice 216. In some embodiments, forexample, the urging is effected by the cutting tool 250 as the piston236 is being retracted. In this respect, in some embodiments, forexample, the flow control member 208, the cutting tool 250 and the port211 are co-operatively configured such that, while the flow controlmember 208 is being retracted relative to the valve seat 218 (i.e. fromthe seated position), the port 211 is disposed to receive thesize-reduced solid debris being urged from the space 223 by the cuttingtool 250 (for conduction into the fluid passage 210) that is translatingwith the flow control member 208.

In some embodiments, for example, the cutting tool 250 includes aplurality of cutting blades extending outwardly from an outer surface.In some embodiments, the distance by which the blades extend outwardlyfrom the outer surface is at least 30/1000 of an inch. In someembodiments, for example, the cutting tool 250 includes grooves disposedbetween the cutting blades. In some embodiments, for example, a set ofthe cutting blades is arranged along a spiral path. In some embodiments,for example, the cutting tool 250 includes a reamer.

In some embodiments, for example, a reciprocating assembly 253 includesat least the piston 236 and the flow control member 208, and, in someembodiments, further includes the cutting tool 250. While the flowcontrol member 208 is seated relative to the valve seat 218, a distalend 253A, of the reciprocating assembly 253, extends through the orifice216 and into the space 223, while being spaced apart from the housing203B. While spaced apart from the housing 203, the distal end 253A issusceptible to deflection from the weight of solid debris which may haveaccumulated within the space 223. To mitigate versus undesirabledeflection, while the flow control member 208 is seated relative to thevalve seat 218, the maximum spacing distance, between the distal end253A and the housing 203B is less than 30/1000 of an inch. In someembodiments, for example, while the flow control member 208 is seatedrelative to the valve seat 218, the distal end 253A is disposed withinthe space 223 (e.g. a passage) that is extending from the orifice 216 tothe one or more ports 212.

Although the valve 202 has been described above as being configured forintegration within an injection string, the valve 202 may be configuredfor integration within a production string and used within a productionstring, which may be in a different well as an offsetting injectionstring or the same well as an injection string, each of the injectionstrings and/or production strings comprising a number of valves 202.

Method of Fault Detection and Recovery in a Tubing String Located in aHydrocarbon Well and Method of Fault Protection in a Tubing StringLocated in a Hydrocarbon

FIG. 9 is a block diagram of a control unit 900 for a flow communicationstation in accordance with one example embodiment of the presentdisclosure. The control unit 900 comprises a line protection circuit 902in a shared data and power cable 901, which in at least some examples isa power-line providing both data and communications via power-linecommutations (PLC), a telecommunications unit 904 for communication withcontrol equipment on the surface 102, a power supply 906 for poweringthe control unit 900, and a motor controller and sensor interface 908for controlling the flow communication station and sensors of the flowcommunication station. In some examples, sensors 904, 952 (FIG. 10) anda motor 960 (FIG. 10) are connected via connector rather thanwire-to-board, although wire-to-board could be used in alternativeembodiments.

In some examples, the motor controller and sensor interface 908 may be acombination of hardware and software as well as the pressure sensorcircuits. In one example, the power supply 906 is a 100-300 Vdc to 60V,15V and 3.3V, 30 W design. The power supply 906 includes a planartransformer.

FIG. 10 is a block diagram of the motor controller and sensor interface908 of FIG. 9. Sensors 952, including pressure sensors and resistancetemperature detectors (RTD), sense pressure and temperature at the flowcommunication station and output the sensed data to a signal conditioner954, which processes the sensed data before output to a microcontroller(MCU) 954. The MCU 956 is connected to and powered by the power supply306 which provides a local protection power input 958. The MCU 956interfaces with a motor driver 960 which drives a motor 962 controllingthe valve 202. The MCU 954 includes a digital communication interfaceand is externally programmable via the telecommunications unit 904 (e.g.telecommunications board). The motor control is bidirectional and allowsoutput current sensing, torque control, detection of stall conditionsand position sensing/memory. Sensor/sensorless control may also beprovided.

Feedback 964 from the motor 960, such as phase current, hall sensors,and phase voltage, are provided to the MU 956. FIG. 11 illustrates adriver circuit of the motor driver 960 in accordance with one embodimentof the present disclosure. FIG. 12 illustrates a switching diagram forthe driver circuit of FIG. 11. FIG. 13 is a general circuit diagramshowing the topography of the power supply of the control unit 900 ofFIG. 9.

For the telemetry system of the flow communication station, data iscoupled to the power conductor using a small isolation transformer andcoupling capacitor. This allows a single conductor to be used in thepower-line and the casing as a return. It is a half-duplex system inwhich only one control unit of a valve 202 can transmit at a time sothat a surface modem controls which control unit is transmitting andwhen that control unit is transmitting. Each control unit has a uniqueaddress so that a relative position of the control unit in the well isknown. In some examples, data modulation is performed by binaryphase-shift keying (BPSK), a form of differential phase-shift keying(DPSK) with an option to be Quadrature phase-shift keying (QPSK) or8-psk depending on data requirements. Pulse Width Modulation (PWM)outputs from a processor of the controller are output into a half bridgedriver that drives a transformer (the coupling network) to shape andcouple the data to the power-line. The half bridge driver is similar toa class D audio amplifier. The data communication may be a serialcommunications protocol such as Modbus or a derivation thereof.

Within an injection wellbore 104A, a shared line is used to provide dataand power to control units 900 for the flow communication station 110.Each control unit 900 is connected in series for both data and power.Conventionally, when a short circuit (e.g., output short circuit) occursin the line, or a control unit fault or failure occurs, the injectionstring ceases to return any data from downhole, effectively causing theinjection well 104 to become inoperable. Examples of control unit faultsand/or failures include over-voltage and under-voltage. When a shortcircuit, control unit fault or failure occurs, data for the injectionwell 104 will not be returned to the control system on the surface 102from the injection string, and the line will have a low voltage even athigh currents. As a result, the injection well 104 is not operational.To restore operation to the valve affected by the short circuit, faultor failure, the injection string must typically be removed from theinjection well 104 for inspection and repair of the short circuit,control unit fault or control unit failure.

FIG. 14 shows a line protection circuit 902 of the control unit of FIG.9 in accordance with one embodiment of the present disclosure will bedescribed. In accordance with the present disclosure, a number of lineprotection circuits 902 are connected in series, one for each flowcommunication station, to form a downhole fault protection system. Asshown in FIG. 14, each line protection circuit 902 comprises a pair offault condition triggered circuit interrupting devices. In the presentexample, the circuit interrupting devices are a pair of fuses comprisinga first fuse 1404 and a second fuse 1406 that together can be used ascircuit breakers to restore the operability of the injection well 104 inthe event of a short circuit or control unit fault. Thus, the downholefault protection system comprises a series of paired fuses, one pair foreach flow communication station 110. The fuses are each triggered tointerrupt current flow when current exceeds a respective fuse thresholdamperage.

The first fuse 1404 is located in a main power-line 1410 and the secondfuse 1406 is located in a branch line 1412 from the main power-line 1410that extends to the power supply 906 of the control unit 900 for therespective flow communication station 110. In some examples, theamperage thresholds of the first fuse 1404 and the second fuse 1406 ofeach fuse pair is the same, although in other examples the amperage maybe different. In some examples, the main power-line 1410 may alsoinclude a NTC (Negative temperature coefficient) thermistor 1414adjacent to a first fuse 1404. An NTC thermistor 1414 is a resistorwhose resistance is dependent on temperature. The NTC thermistor 1414acts as a heater. The NTC thermistor 1414 of the line protectioncircuits 1400 are matched such that the operating temperatures of thefirst fuses 1404 differ by less than a threshold amount so that thefirst fuses 1404 at the flow communication stations have the same orsimilar operating temperatures, increasing the reliability androbustness of the downhole fault protection system when fuses havingsimilar temperature characteristics are used. Although not shown, inother embodiments, a NTC thermistor may be located in each branch line1412 adjacent to the second fuse 1406, the NTC thermistors in the branchlines 1412 being matched such that the operating temperatures of thesecond fuses 1406 differ by less than a threshold amount so that thesecond fuses 1406 at the flow communication stations 110 have the sameor similar operating temperatures.

The threshold amperage of each pair of fuses is staggered (or stepped)and decreases from the heel to the toe of the injection well 104.Accordingly, the pair of fuses 1404, 1406 associated with flow controlstation 110A have greater threshold amperages than the pair of fusesassociated with adjacent downhole flow control station 110B, and so on,with the pair of fuses associated with final flow control station 110Ehaving the lowest threshold amperages. The difference in amperage of thefirst fuse 1404 or between the first fuses 1404 is selected to allow thesequential overloading/blowing of the first fuses 1404 from toe to theheel by steadily increasing the current in the line. Example differencesin amperages between each pair of fuses is 50-200 mA, 100-150 mA and100-110 mA, but this is variable depending on the tolerance of the fusesand available amperages, which may vary by manufacture, etc. When ashort circuit, control unit fault or control unit failure occurs, thecurrent in the main power-line can be steadily increased to sequentiallytrigger/blow the paired fuses from the toe to heel of the injection well104 until the control unit having the short circuit, control unit faultor control unit failure is disconnected, and the operability of theinjection well is restored. When the fuse associated with a valve havingthe short circuit or control unit fault or failure is blown, data flowfrom the remaining connected control units 900 will return and theoperability of the injection well 104 is restored. However, all flowcommunication stations 110 downhole of the blown fuse will no longer beoperable. The operator of the injection well 104 can decide whether tocontinue operating the injection string with the reduced number of flowcommunication stations 110, or whether to remove the injection stringfrom the injection well 104 for inspection and repair of the shortcircuit, control unit fault or control unit failure.

Referring to FIG. 15, a method 1500 of fault detection and recovery in atubing string located in a hydrocarbon well in accordance with oneexample embodiment of the present disclosure will be described. Thetubing string has a plurality of valves. Each valve has a control unit900. Each control unit 900 is connected in series to a power-lineproviding power and communication. Each of the control units 900 isindependently controllable. The method 1500 may be performed at least inpart by the PLC 606, which is connected to the control units 900, andcommunicates with the control units 900 via half-duplex communication.The tubing string may be an injection string in some examples.

At operation 1502, causing a condition of the valves of the tubingstring to be set in accordance with a first valve configuration. Thefirst valve configuration is defined by a condition of the valves inwhich each valve in the plurality of valves is in either the fully openposition or the fully closed position.

At operation 1504, an injection fluid is caused to be injected into thetubing string while in the first valve configuration.

At operation 1506, a short circuit, fault or failure is detected in oneof the control units of the tubing string via an output of thepower-line. The short circuit, fault or failure may be detected inresponse to a determination that one or more characteristics of theoutput of the power-line has changed by more than a threshold amount.The one or more characteristics of the output of the power-line may be acurrent of the power-line.

At operation 1508, individual control units are caused to be selectivelyisolated from the power-line via a circuit interrupting device. Theindividual control units may be selectively isolated in an isolationsequence. The isolation sequence may be from a toe to a heel of thehydrocarbon well.

At operation 1510, one or more control units associated with the shortcircuit, fault or failure are determined via the output of thepower-line while individual control units are selectively isolated fromthe power-line.

At operation 1512, the one or more control units associated with theshort circuit, fault or failure are selectively isolated from thepower-line. As a result of this, communication between the control units900 and the PLC 606 are restored.

At operation 1514, causing a condition of the valves of the tubingstring to be set in accordance with a second valve configuration. Thesecond valve configuration may be the same or different from the firstvalve configuration. The second valve configuration excludes aspossibilities operating states in which the one or more control unitsassociated with the short circuit, fault or failure selectively isolatedfrom the power-line are controlled.

At operation 1514, causing a condition of the valves of the tubingstring to be set in accordance with a second valve configuration. Thesecond valve configuration may be the same or different from the firstvalve configuration. The second valve configuration excludes aspossibilities operating states in which the one or more control unitassociated with the short circuit, fault or failure selectively isolatedfrom the power-line are controlled.

At operation 1516, an injection fluid is caused to be injected into thetubing string in accordance with a second valve configuration.

In some examples, each control unit 900 has a respective circuitinterrupting device and the power-line comprises a main power-line and aplurality of branch power-lines connected to the main power-line. Thecontrol units 900 for the valves 202 are connected to a respectivebranch power-line. In some examples, each circuit interrupting devicecomprises: a first circuit interrupting device located in a mainpower-line to interrupt current in the main power-line when an amperagethreshold is exceeded; and a second circuit interrupting device locatedin a respective branch line from the main power-line connected to apower supply of a respective control unit of a respective valve tointerrupt current in the respective branch line when an amperagethreshold is exceeded. The amperage thresholds of the first circuitinterrupting device and second circuit interrupting device of eachcircuit interrupting device decreases in a descending order from a heelof the hydrocarbon well to a toe of the hydrocarbon well. The firstcircuit interrupting device and second circuit interrupting device maybe fuses.

Referring to FIG. 16, a method 1600 of downhole fault protection inaccordance with one example embodiment of the present disclosure will bedescribed. First, a downhole fault protection system is provided (block1602). The downhole fault protection system comprises a main power-line1410 having a plurality of branch lines 1412 connected thereto, acontrol unit 900 for a valve 202 connected to each of the branch lines1412, a line protection circuit 1400 for each of the control unit, eachline protection circuit 1400 comprising a pair of fuses, a first fuse1404 in each pair located in the main power-line 1410 and a second fuse1416 in each pair located in a respective branch line 1412 from the mainpower-line that extends to a power supply 906 of the respective controlunit 900 of a respective valve 202, wherein the amperage of the firstfuse 1404 and second flise 1406 is the same, wherein the amperage of thepair of fuses in the line protection circuits 1400 decreases in adescending order from a heel of the injection well 104 to a toe of theinjection well 104.

Next, a short circuit, control unit fault or control unit failure isdetected, typically by a control system at the surface 102 (block 1604).

Next, a current in the main power-line is steadily increased tosequentially trigger the paired fuses from the toe to the heel of theinjection well 104 until the control unit 900 having the short circuit,control unit fault or control unit failure is disconnected and theoperability of the injection well 104 is restored (block 1606).

Although the foregoing description is based on an example application toan injection string in an injection well, the method of fault detectionand recovery in a tubing string located in a hydrocarbon well, method offault protection in a tubing string located in a hydrocarbon, apparatusand system described above may also be adapted for use in a productionstring in a production well.

General

The steps and/or operations in the flowcharts and drawings describedherein are for purposes of example only. There may be many variations tothese steps and/or operations without departing from the teachings ofthe present disclosure. For instance, the steps may be performed in adiffering order, or steps may be added, deleted, or modified.

The coding of software for carrying out the above-described methodsdescribed is within the scope of a person of ordinary skill in the arthaving regard to the present disclosure. Machine-readable codeexecutable by one or more processors of one or more respective devicesto perform the above-described method may be stored in amachine-readable medium such as the memory of the data manager. Theterms software and firmware are interchangeable within the presentdisclosure and comprise any computer program stored in memory forexecution by a processor, comprising Random Access Memory (RAM) memory,Read Only Memory (ROM) memory, EPROM memory, electrically EPROM (EEPROM)memory, and non-volatile RAM (NVRAM) memory. The above memory types areexamples only, and are thus not limiting as to the types of memoryusable for storage of a computer program.

All values and sub-ranges within disclosed ranges are also disclosed.Also, although the systems, devices and processes disclosed and shownherein may comprise a specific plurality of elements, the systems,devices and assemblies may be modified to comprise additional or fewerof such elements. Although several example embodiments are describedherein, modifications, adaptations, and other implementations arepossible. For example, substitutions, additions, or modifications may bemade to the elements illustrated in the drawings, and the examplemethods described herein may be modified by substituting, reordering, oradding steps to the disclosed methods.

Features from one or more of the above-described embodiments may beselected to create alternate embodiments comprised of a subcombinationof features which may not be explicitly described above. In addition,features from one or more of the above-described embodiments may beselected and combined to create alternate embodiments comprised of acombination of features which may not be explicitly described above.Features suitable for such combinations and subcombinations would bereadily apparent to persons skilled in the art upon review of thepresent application as a whole.

In addition, numerous specific details are set forth to provide athorough understanding of the example embodiments described herein. Itwill, however, be understood by those of ordinary skill in the art thatthe example embodiments described herein may be practiced without thesespecific details. Furthermore, well-known methods, procedures, andelements have not been described in detail so as not to obscure theexample embodiments described herein. The subject matter describedherein and in the recited claims intends to cover and embrace allsuitable changes in technology.

Although the present disclosure is described at least in part in termsof methods, a person of ordinary skill in the art will understand thatthe present disclosure is also directed to the various elements forperforming at least some of the aspects and features of the describedmethods, be it by way of hardware, software or a combination thereof.Accordingly, the technical solution of the present disclosure may beembodied in a non-volatile or non-transitory machine-readable medium(e.g., optical disk, flash memory, etc.) having stored thereonexecutable instructions tangibly stored thereon that enable a processingdevice to execute examples of the methods disclosed herein.

The term processor may comprise any programmable system comprisingsystems using microprocessors/controllers or nanoprocessors/controllers,digital signal processors (DSPs), application specific integratedcircuits (ASICs), field-programmable gate arrays (FPGAs) reducedinstruction set circuits (RISCs), logic circuits, and any other circuitor processor capable of executing the functions described herein. Theterm database may refer to either a body of data, a relational databasemanagement system (RDBMS), or to both. As used herein, a database maycomprise any collection of data comprising hierarchical databases,relational databases, flat file databases, object-relational databases,object oriented databases, and any other structured collection ofrecords or data that is stored in a computer system. The above examplesare example only, and thus are not intended to limit in any way thedefinition and/or meaning of the terms “processor” or database.

The present disclosure may be embodied in other specific forms withoutdeparting from the subject matter of the claims. The described exampleembodiments are to be considered in all respects as being onlyillustrative and not restrictive. The present disclosure intends tocover and embrace all suitable changes in technology. The scope of thepresent disclosure is, therefore, described by the appended claimsrather than by the foregoing description. The scope of the claims shouldnot be limited by the embodiments set forth in the examples, but shouldbe given the broadest interpretation consistent with the description asa whole.

The invention claimed is:
 1. A method of fault detection and recovery ina tubing string located in a hydrocarbon well, the tubing string havinga plurality of valves, each valve having a control unit, each controlunit being connected in series to a power-line providing power andcommunication, each of the control units being independentlycontrollable, the method comprising: detecting a short circuit, fault orfailure in the tubing string via an output of the power-line, whereinthe short circuit, fault or failure occurs in one of the control unitsof the tubing string; causing individual control units to be selectivelyisolated from the power-line via a circuit interrupting device; anddetermining one or more control units associated with the short circuit,fault or failure via the output of the power-line while individualcontrol units are selectively isolated from the power-line; wherein thepower-line comprises a main power-line and a plurality of branchpower-lines connected to the main power-line; wherein the control unitsfor the valves are each connected to a respective branch power-line; andwherein each control unit has a respective circuit interrupting devicecomprising: a first circuit interrupting device located in the mainpower-line to interrupt current in the main power-line when an amperagethreshold is exceeded; and a second circuit interrupting device locatedin the respective branch power-line connected to a power supply of arespective control unit of a respective valve to interrupt current inthe respective branch power-line when an amperage threshold is exceeded.2. The method of claim 1, wherein the short circuit, fault or failure isdetected in response to a determination that one or more characteristicsof the output of the power-line has changed by more than a thresholdamount.
 3. The method of claim 2, wherein the one or morecharacteristics of the output of the power-line is a current of thepower-line.
 4. The method of claim 1, wherein the method is performed bya master controller coupled to the control units.
 5. The method of claim4, wherein the master controller is located above the hydrocarbon well.6. The method of claim 4, wherein the control units communicate with themaster controller via half-duplex communication.
 7. The method of claim4, wherein the master controller is a programmable logic controller. 8.The method of claim 1, wherein the tubing string is an injection string.9. The method of claim 1, comprising: after the determining one or morecontrol units associated with the short circuit, fault or failure,restoring communication on the power-line by selectively isolating theone or more control units associated with the short circuit, fault orfailure from the power-line.
 10. The method of claim 9, comprising:before detecting the short circuit, fault or failure: causing acondition of the valves of the tubing string to be set in accordancewith a first valve configuration; and causing an injection fluid to beinjected into the tubing string in accordance with a first valveconfiguration; after the determining one or more control unitsassociated with the short circuit, fault or failure: causing a conditionof the valves of the tubing string to be set in accordance with a secondvalve configuration, wherein the second valve configuration excludes aspossibilities operating states in which the one or more control unitsassociated with the short circuit, fault or failure selectively isolatedfrom the power-line are controlled; and causing the injection fluid tobe injected into the tubing string in accordance with the second valveconfiguration, wherein each of the first valve configuration and secondvalve configuration is defined by a condition of the valves in whicheach valve in the plurality of valves is in either the fully openposition or the fully closed position.
 11. The method of claim 1,wherein the individual control units are selectively isolated in anisolation sequence.
 12. The method of claim 11, wherein the isolationsequence is from a toe to a heel of the hydrocarbon well.
 13. The methodof claim 1, wherein the amperage thresholds of the first circuitinterrupting device and second circuit interrupting device of eachcircuit interrupting device decreases in a descending order from a heelof the hydrocarbon well to a toe of the hydrocarbon well.
 14. Acontroller for controlling control units of a tubing string located in ahydrocarbon well, the tubing string having a plurality of valves, eachvalve having a control unit, each control unit being connected in seriesto a power-line providing power and communication, each of the controlunits being independently controllable, the controller comprising: aprocessor; and a memory coupled the at least one processor, the memoryhaving tangibly stored thereon executable instructions for execution bythe processor that, when executed by the processor, cause the controllerto: detect a short circuit, fault or failure in the tubing string via anoutput of the power-line, wherein the short circuit, fault or failureoccurs in one of the control units of the tubing string; causeindividual control units to be isolated from the power-line via acircuit interrupting device; and determine one or more control units isassociated with the short circuit, fault or failure via the output ofthe power-line while individual control units are isolated from thepower-line; wherein the power-line comprises a main power-line and aplurality of branch power-lines connected to the main power-line;wherein the control units for the valves are each connected to arespective branch power-line; and wherein each control unit has arespective circuit interrupting device comprising: a first circuitinterrupting device located in the main power-line to interrupt currentin the main power-line when an amperage threshold is exceeded; and asecond circuit interrupting device located in the respective branch lineconnected to a power supply of a respective control unit of a respectivevalve to interrupt current in the respective branch line when anamperage threshold is exceeded.
 15. A downhole fault protection systemfor a tubing string located in a hydrocarbon well, the tubing stringhaving a plurality of valves, each valve having a control unit, eachcontrol unit being connected in series to a power-line providing powerand communication, each of the control units being independentlycontrollable, the system comprising: a main power-line having aplurality of branch lines connected thereto; a control unit for a valveconnected to each of the branch lines; a line protection circuit foreach of the control units, each line protection circuit comprising apair of circuit interrupting devices, a first circuit interruptingdevice in each pair located in the main power-line to interrupt currentin the main power-line when an amperage threshold is exceeded and asecond circuit interrupting device in each pair located in a respectivebranch line from the main power-line that extends to a power supply of arespective control unit of a respective valve to interrupt current inthe respective branch line when an amperage threshold is exceeded;wherein the amperage thresholds of the first and second circuitinterrupting devices decreases in a descending order from a heel of thehydrocarbon well to a toe of the hydrocarbon well, enabling valves to beselectively isolated in order from the toe to the heel by increasing acurrent applied to the line protection circuits.
 16. The downhole faultprotection system of claim 15, wherein the difference in amperagethresholds between adjacent pair of circuit interrupting devices is50-200 mA, preferably 100-150 mA, and more preferably 100-110 mA. 17.The downhole fault protection system of claim 15, wherein the lineprotection circuit further comprises a NTC (Negative temperaturecoefficient) thermistor adjacent to the first circuit interruptingdevice in the main power-line, wherein the NTC thermistor of the lineprotection circuits are matched such that the operating temperatures ofthe first circuit interrupting devices differ by less than a thresholdamount.
 18. The downhole fault protection system of claim 15, whereinthe first and circuit interrupting devices are fuses.
 19. A downholefault protection system for multiple stages of downhole valves in awell, comprising: a main power-line having a plurality of branch linesconnected thereto; a control unit for a valve connected to each of thebranch lines; a line protection circuit for each of the control units,each line protection circuit comprising a circuit interrupting devicefor isolating the valve from the main power-line when an amperagethreshold at the control unit is exceeded; wherein the amperagethresholds of the circuit interrupting devices decreases in a descendingorder from a heel of the hydrocarbon well to a toe of the hydrocarbonwell, enabling valves to be selectively isolated in order from the toeto the heel by increasing a current applied to the line protectioncircuits.
 20. A method of fault detection and recovery in a tubingstring located in a hydrocarbon well, the tubing string having aplurality of valves, each valve having a control unit, each control unitbeing connected in series to a power-line providing power andcommunication, each of the control units being independentlycontrollable, the method comprising: causing a condition of the valvesof the tubing string to be set in accordance with a first valveconfiguration; causing an injection fluid to be injected into the tubingstring in accordance with a first valve configuration; detecting a shortcircuit, fault or failure in the tubing string via an output of thepower-line, wherein the short circuit, fault or failure occurs in one ofthe control units of the tubing string; causing individual control unitsto be selectively isolated from the power-line via a circuitinterrupting device; determining one or more control units associatedwith the short circuit, fault or failure via the output of thepower-line while individual control units are selectively isolated fromthe power-line; restoring communication on the power-line by selectivelyisolating the one or more control units associated with the shortcircuit, fault or failure from the power-line; causing a condition ofthe valves of the tubing string to be set in accordance with a secondvalve configuration, wherein the second valve configuration excludes aspossibilities operating states in which the one or more control unitsassociated with the short circuit, fault or failure selectively isolatedfrom the power-line are controlled; and causing the injection fluid tobe injected into the tubing string in accordance with the second valveconfiguration, wherein each of the first valve configuration and secondvalve configuration is defined by a condition of the valves in whicheach valve in the plurality of valves is in either the fully openposition or the fully closed position.